The present invention relates to energy service and distribution networks, and more particularly to networks having multiple generation sources and loads that are geographically separated by distances greatly in excess of one hundred miles.
Large industrial load centers like Los Angeles, San Francisco, New York, etc., in the United States often import up to 40% of their power from outside resources. The major load centers are often part of an extensive electrical power grid. In most of the country, the transmission paths which bring this power are fairly long as the generation is located at far away places, and they are generally very heavily loaded. In addition to the thermal limitations on some transmission lines or other series line components, the transmission of power on these long paths is limited by transient and dynamic instability at high levels of power imports. The transmission paths are also, at times, heavily loaded because of unscheduled power flow or loop flow on these paths. This limits the capability of theses systems to import power. Levels of import beyond an acceptable limit results in power oscillations between the different regions of the system and can often result in system breakups. These oscillations generally occur at frequencies in the range of 0.2-0.8 Hz. Such oscillations between the northwest and southwest also lead to a major system disturbance in the western United States on Aug. 10, 1996.
The Western States Coordinating Council (WSCC) system is a very large, inter-connected system and covers a wide geographical area. Because of the large power system connected with the long transmission lines, some of the major areas can suffer from power system oscillations with respect to other areas. These inter-area oscillations occur at very low frequencies ranging between 0.20 and 1.0 Hz. The large load/generation centers act like masses in a spring-mass system, whereas the transmission lines act as springs giving rise to a multitude of frequencies in the above range. These low oscillation frequencies are typical of large masses connected by a relatively weak transmission system and thus limit the power transfers on the interconnected transmission lines. These oscillations occur when two large areas in an interconnected power system swing with respect to each other. This swing is characterized by power flow back and forth from one area to another. Normally such power flow oscillations are damped by the system damping, but if the interconnecting system is relatively weak, the oscillations can grow also. Moreover, major areas are often influenced by two or more distant areas, oscillations of different frequencies being superimposed.
FIG. 1 shows some of the large power generation/load areas in an existing power network of the southwestern United States. The areas are represented as masses and the transmission lines are represented as springs connected to these areas. Some of the major areas in the WSCC system of interest are:
1. The Pacific Northwest, including the western part of Canada, Washington and Oregon, designated Area M1; PA1 2. Northern California, including PG&E, SMUD, etc., designated Area M2; PA1 3. Southern California Edison, LA DWP and San Diego Gas and Electric, designated Area M3; and PA1 4. Arizona and New Mexico, designated Area M4. PA1 (a) monitoring deviations in at least one of frequency or phase of the alternating current power; and PA1 (b) dynamically offsetting the real power operating point in correspondence with the monitored deviations. PA1 (a) setting a threshold level of the monitored deviations; and PA1 (b) inhibiting the step of dynamically offsetting until the deviations exceed the threshold level. PA1 (a) comparing an operating range of the at least one valve with a desired operating range being the medial valve opening region; and PA1 (b) adjusting a nominal setting of the at least one valve for centering the operating range thereof relative to the medial valve opening region. PA1 (a) maintaining phasor data defining orthogonal real power and reactive vectors associated with the network geographically local to the power control element; and PA1 (b) determining deviations in phase of the real power vector. PA1 (a) maintaining a positive sequence vector defining a composite voltage phase and magnitude of the network; and PA1 (b) extracting the voltage phase from the vector. PA1 (a) monitoring deviations in real power within a frequency bandwidth of between approximately 0.2 Hz and approximately 1.0 Hz; and PA1 (b) dynamically offsetting the real power operating point in correspondence with the monitored deviations. PA1 (a) maintaining phasor data defining orthogonal real power and reactive vectors associated with the network; and PA1 (b) extracting a real power component of the phasor data. PA1 Alternatively, or in addition, the step of monitoring can include the steps of: PA1 (a) maintaining a positive sequence vector defining a composite voltage phase and magnitude of the network; and PA1 (b) extracting the voltage magnitude from the vector.
Areas M1 and M4 typically oscillate with respect to Area 3, depending on the fault, post fault system condition, or the location and severity of the system disturbance. The Pacific Northwest swings at about 0.3 Hz and Arizona-New Mexico swings at about 0.7 Hz with respect to California. Generally when system swings occur, they are multimodal and both the modes can be observed simultaneously in the Southern California area.
The oscillations are generally well damped. The damping level, however, depends on the power transfer levels on various transmission paths. The damping usually takes a few (10-15) seconds. However, if the power transfer levels are high, the oscillation amplitudes either continue to grow or remain undamped and can result in a break up of the system by tripping of the transmission lines. Under normal system operation conditions, these oscillation modes, although present, are of very small magnitude (-60 to -80 dB) and are fully damped. However, a fault in the system, a large generator trip or a major load drop or line outage can excite these oscillation modes with large power movements from one area to the other.
Power system stabilizers are known, having a primary purpose of providing damping on the system to counteract the undamping resulting from the use of modern fast acting excitation systems. The stabilizers, which are applied on the excitation system of generating machines, were initially used for damping the oscillations of an individual machine with respect to the rest of the system, otherwise known as local mode oscillations (2.0-4.0 Hz). A power system stabilizer basically modulates the machine voltage to control the voltage oscillations through the generator exciter by extracting low frequency rotor oscillations from a speed signal. Because the power system stabilizers of the prior art act through the excitation system, they can only control the reactive power output of the generators, there being little if any control of the real power output. Thus the stabilizers of the prior art typically feed exciters with control signals that are derived from measurements of reactive power. The real power in a generator is primarily controlled by a governor of the machine, the governor incorporating integral compensation for imparting control stability thereto.
There have been attempts to stabilize power system oscillations over the last 25 plus years, using the power system stabilizers feeding machine excitation systems as described above. The signal injected by the power system stabilizer in the excitation system results in change of the voltage at the generation machine terminals. This change in voltage also results in some slight change on the machine power output. This concept modulates the machine's reactive power output mostly. A small degree of real power control is, however, achieved through the change in the terminal voltage caused by the excitation system. If this machine output change happens to be in opposition to the oscillations that are occurring in the system, then the power system stabilizer is able to stabilizer the system power oscillators. However, this approach is ineffective when, as often happens, the machine output is not in opposition to the oscillations.
There have also been attempts to control power generators by injecting signals into the machine governor loops in order to alter the machine power output. A frequency deviation error signal for this purpose can be derived from monitored frequency or power signals of the system. These attempts have been unsuccessful because the governors of the generators that were the subject of the past attempts were generally slow. Also, the attempts were directed to oscillation frequencies of mostly local mode oscillations, being in the range of 1.0 to 3.0 Hz.
Thus there is a need for improved methods and circuitry for compensating against inter-area or regional oscillations of a power distribution network for permitting greater utilization of the available generating capacity.